1. Field of the Invention
The present invention relates to coiled tubing drilling systems. More particularly, the present invention relates to removing drilled cuttings from a well bore during coiled tubing drilling operations. In one embodiment, the invention relates to enhancing the coiled tubing so as to facilitate removal of “cuttings beds” in a “deviated” well bore.
2. Related Art
In the field of oil well drilling, coiled tubing (CT) is becoming an increasingly common replacement for traditional steel segmented pipe in order to meet the demands of drilling deviated and horizontal wells. Conventional drill strings consist of hundreds of straight steel tubing segments that are screwed together at the rig floor as the string is lowered down the well bore. With coiled tubing (CT), the drill string consists of one or more continuous lengths of CT that are spooled off one or more drums or spools and connected together for injection into the well bore from a rig as drilling progresses. Another major difference between conventional rotary drilling and CT drilling is the absence of drill pipe rotation. By using CT, much of the time, effort, and opportunity for error and injury are eliminated from the drilling process.
Coiled tubing, as currently deployed in the oilfield industry, generally includes small diameter cylindrical tubing made of metal or composites that have a relatively thin cross sectional thickness. CT is typically much more flexible and much lighter than conventional drill string. Thus, CT is particularly suited to drilling horizontal and other deviated wells where bending and flexing of the drill pipe is necessary. These characteristics of CT have led to its use in various well operations. CT is introduced into the oil or gas well bore through wellhead control equipment to perform various tasks during the exploration, drilling, completion, production, and workover of a well. For example, CT is routinely utilized to inject gas or other fluids into the well bore, inflate or activate bridges and packers, transport well logging tools downhole, perform remedial cementing and clean-out operations in the well bore, and to deliver drilling tools downhole.
FIG. 1 shows a simple illustration of how CT is utilized in an oil well drilling application. The CT drill string 10 is stored on a reel or drum 110. As the drill string 10 is spooled off the reel 110 and directed toward the rig 120, the tubing passes through a set of guide rollers 130 attached to a levelwind 140. The levelwind 140 is used to control the position of the CT as it is spooled off and onto the service reel 110. As the tubing approaches the rig 120, it contacts the gooseneck or guide arch 150. The tubing guide arch 150 provides support for the tubing and guides the tubing from the service reel through a bend radius prior to entering an injector 160 on the rig 120. The tubing guide arch 150 may incorporate a series of rollers that center the tubing as it travels over the guide arch and towards the injector 160. The injector 160 grips the outside of the tubing and controllably provides forces for tubing deployment into and retrieval out of the well bore. It should be noted that the rig 120 shown in FIG. 1 is a simple representation of a rig. Those skilled in the art will recognize that various components are absent from FIG. 1. For instance, a fully operational rig may include a series of valves or spools as would be found on a christmas tree or a wellhead. Such items have been omitted from FIG. 1 for clarity.
Early iterations of CT were metallic in structure, consisting for instance of carbon steel, corrosion resistant alloys, or titanium (MCT). These coiled tubes were fabricated by welding shorter lengths of tubing into a continuous string. More recent designs have incorporated composite materials. Composite coiled tubing (CCT) includes various materials, as for example: fiberglass, carbon fiber, and Polyvinylidene Fluoride (PVDF). The fiberglass and carbon fiber are in an epoxy or resin matrix and wrapped around a PVDF tube. These materials are generally desirable in CT applications because they are lighter and more flexible, and therefore less prone to fatigue stresses induced over repeated trips into the well or due to the heave of floating drilling vessel.
In removing drilled cuttings from any well, drilling fluids circulated in the well suspend the cuttings and carry them to the surface for removal from the well. Mud is typically pumped down through the inner flow bore of the drill string, out through the bit at the bottom of the borehole, and back up through the annulus formed between the drill string and borehole wall. In a vertical hole, the velocity vector counters the gravity vector. When the velocity vector opposes the gravity vector, the cuttings can be easily suspended and lifted in the vertical borehole. Thus, removal of drilled cuttings from a substantially vertical well presents little problems. However, in drilling deviated and horizontal wells, the velocity vector deviates from vertical and is sometimes horizontal, while the gravity vector remains vertical. In this situation, the cuttings tend to settle to the bottom of the hole away from the fluid flow. Such deposits are commonly called “cuttings beds.” As used herein, the term “deviated” with respect to wells shall be understood to include any well at sufficient angle or deviation from vertical that cuttings beds tend to form during the drilling operation. “Deviated” wells shall be understood to include without limitation “angled,” “high-angled,” “oval,” “eccentric,” “directional” and “horizontal” wells, as those terms are commonly used in the oil and gas industry. A “highly deviated” well is defined as a well having an angle of 45° to 90° from vertical.
The cuttings beds problem is exacerbated when obstructions in the fluid path through the deviated borehole disrupt the fluid velocities, especially on the low side of the borehole. Due to the gravity force, the CT drill pipe tends to lie on the low side of the hole when drilling deviated well bores.
Referring to FIGS. 3A, B and C, the drill bit (not shown) forms cuttings as the bit drills into the formation causing the formation of cuttings beds 20 in deviated well drilling. In FIG. 3A, the non-rotating drill string 10 is shown resting against the bottom 12 of a horizontal or deviated borehole 14. The cuttings from the bit are shown settling underneath drill string 10 and in the arcuate areas on each side of the lower side of the drill string in area 16 as shown in FIG. 3B to form cuttings beds 20. In FIG. 3B, the returning drilling fluid tends to flow most vigorously through the larger upper arcuate area 18 of annulus 30 above drill string 10. Upper portion 18 is the path of least resistance for the fluid flow, thereby causing a minimal fluid flow around the bottom of drill string 10 adjacent the cuttings beds 20. This phenomenon is represented by the velocity profile of FIG. 3C. The slower fluid flowing around the bottom of drill string 10 is unable to keep the cuttings entrained, thus gravity causes them to settle out and gather in area 16 thereby forming cuttings beds 20. The cuttings then tend to accumulate and bury drill string 10.
Buildup of cuttings beds can lead to stuck pipe, reduced weight on the bit leading to reduced rate of penetration, undesirable friction, restricted movement, transient hole blockage leading to lost circulation conditions, excessive drill pipe wear, extra cost for special mud additives and wasted time by wiper trip maneuvers. Cuttings also reduce the interval of wells that can be drilled with CT. Cuttings beds are especially problematic in extended reach drilling and in wells using invert emulsion type drilling fluids.
Cleaning (i.e., removing drilled cuttings from) a deviated well, particularly drilled at a high angle, can be difficult. One of the critically limiting factors in drilling with CT is the inability to clean the hole in deviated wells. This inability is caused largely by the small diameter tubing and tools usually associated with CT and CT bottom hole assemblies. The small diameter restricts the drilling fluid volume and velocity which can be achieved through the tubing and tools, thus reducing the annular volume and velocity of the drilling fluid that can be used to transport the cuttings from the borehole. Further, in CT drilling, the CT does not rotate so there is little mechanical action to stir the cuttings off of the low side of the borehole. Other factors contributing to inadequate hole cleaning include limited pump rate, drill pipe eccentricity (positioning of the CT in the well bore; low side=+100% eccentricity, high side=−100% eccentricity), sharp build rates, high bottom hole temperatures, and oval shaped well bores. In turn, inadequate hole cleaning can lead to cuttings beds buildup in the wellbore.
Various methods have been tried to remove cuttings which usually settle on the low side of a deviated borehole. One method, marginally successful at best, is to vary the drilling fluid/medium properties, regimes, and rates. Well treatments or circulation of fluids specially formulated to remove cuttings beds are sometimes used to prevent buildup to the degree that they interfere with the drilling apparatus or otherwise with the drilling operation. Two commonly used types of fluids that have been applied with limited success are highly viscous fluids, having greater viscosity or density than the drilling fluids being used in the drilling operation, and lower viscosity fluids, having less viscosity or density than the drilling fluids being used in the drilling operation. Commonly, the drilling operation must be stopped while such fluids are swept through the wellbore to remove the cuttings.
Alternatively, or additionally, special viscosifier drilling fluid additives have been proposed to enhance the ability of the drilling fluid to transport cuttings. In one embodiment, the viscosifier is introduced into the drilling fluid by a pill. However, such additives at best merely delay the buildup of cutting beds and can be problematic if they change the density of the drilling fluid.
More specifically, this method includes high density and low density sweeps. In other words, a volume of high density drilling mud is pumped down the drill string flowbore followed by a volume of low density drilling mud. For example, the drilling system may be using 9 pound drilling mud. Then, a 2 or 3 barrel kill of a heavy weight mud may be pumped down the flowbore. Once the slug of heavy weight mud passes through the flowbore and bit, it enters the annulus where the surrounding drilling fluid is much lighter. As gravity acts on the different density fluids, a distinct disparity is created in the annulus with the heavy weight mud moving toward the bottom of the borehole. This causes the velocity profile of FIG. 3C to shift downward such that more of the fluids toward the bottom of drill string 10 are moving faster. Consequently, some of cuttings 20 are re-suspended in the fluid flow and carried to the surface. However, the velocity profile may not be shifted enough to carry away a significant portion of the cuttings, whereby most of the cuttings are still trapped underneath drill string 10. It should be noted that this prior art method is directed to shifting the velocity profile in the deviated borehole.
An ancillary procedure to fluid additives includes the use of foam to clean the borehole. Large volumes of gas are injected into the mud causing the drilling fluid to have bubbles, which then serve to clean the borehole. The gas flux creates an in situ foam for cleaning the hole. This may create under balance drilling. The use of foam to clean the borehole is in the prior art. However, foam sweeps and gas influx could be used in combination with other prior art embodiments, as well as embodiments and solutions of the present invention.
Mechanical means have also been employed to remove cuttings beds from the bottom of a deviated borehole. One of the simplest is rotating the drill pipe. Rotating the drill pipe agitates cuttings gathering at the bottom of a deviated well bore. The cuttings are lifted from the bottom, suspended in the moving drilling fluid, and carried to the surface. However, CCT and MCT are typically not rotated in the borehole. Thus, the CT tends to settle on the bottom of the borehole, allowing drilled cuttings to accumulate at the bottom of the borehole where the fluid velocity and volume is minimal. It should be understood that the present invention particularly applies to non-rotating drill pipe.
It has been proposed that composite pipe be made in sections and connected by joints such that the jointed composite drill pipe can be rotated while drilling a well. See, for example, International Publication W 01/09478A1 published Feb. 8, 2001. Studies have been made for rotating jointed composite pipe in a drilling system. However, the effectiveness of jointed composite pipe is unproven. Furthermore, as noted above, the focus of the present application is on non-rotating drill pipe without regard to the material that the pipe is made of. Thus, it is irrelevant whether the drill pipe is jointed or coiled tubing; application of the present invention depends on whether the drill pipe is rotated or not.
Another mechanical operation for removing cuttings beds has also been used wherein the drill string is pulled back along the well, pulling the bit through the horizontal or deviated section of the well. Dragging the bit back up the borehole stirs up cuttings in the cuttings beds to better enable the drilling fluid to transport the cuttings up the well. The bit is typically pulled back to the location where the borehole is no longer highly deviated. However, such dragging of the bit can damage its gage side, and dragging the bit while rotating, further reams the hole. Also, such “wiper trips” are time consuming which increases drilling costs for the well and delays the ultimate completion of the well.
Another prior art mechanical device is a hydraulic oscillator which acts as a vibrator on the end of the drill string. The hydraulic oscillator shakes the drill string to loosen cuttings that have been packed together underneath and adjacent to that portion of the drill string positioned on the bottom of the deviated borehole. However, it has been found that the vibrator works only on the cuttings beds that are in close proximity to the vibrator, and not beds that extend continuously up the entire length of the tubing string present in the deviated portion of the wellbore. Generally, the vibrations are only effective up to 15 or 20 feet on either side of the hydraulic oscillator.
An alternative mechanical operation for removing cuttings beds has been proposed that employs drilling with CT and injecting fluid into the wellbore through the tubing at a flow rate exceeding the flow rate range used for drilling, as discussed in U.S. Pat. No. 5,984,011 ('011 patent), entitled Method for Removal of Cuttings from a Deviated Wellbore Drilled with Coiled Tubing. However, this operation calls for special equipment and requires that drilling be stopped during the treatment, resulting in delays and increased drilling costs.
More specifically, the '011 patent discloses a valve placed above the bit to increase the fluid flow rate up the annulus. The method taught by the '011 patent involves placing a nozzle with a valve at the upper end of the bottom hole assembly, halting drilling operations, and opening the valve. The flow rate of drilling fluid passing through the nozzle is increased, which washes away any cuttings that had collected around the drill string. This is called by-pass circulation, and the device used to create by-pass circulation is generally called a circulation sub. The '011 patent teaches a particular range of return fluid flow rates up the annulus to remove the cuttings.
The drilling system that is the subject of U.S. Pat. No. 6,296,066 ('066 patent), entitled Well System, also discloses a circulation sub. Nozzles are disposed at the connection of the CCT to the upper end of the bottom hole assembly to provide direct flow into the annulus.
However, neither of the previous circulation sub methods works satisfactorily. By-pass circulation works to properly agitate cuttings beds if the nozzle is sized to create flow rates that place the fluid around the drill pipe into turbulent flow. Turbulent flow lifts the cuttings off the bottom of the borehole. Unfortunately, turbulent flow only occurs at a location very close to the circulation sub. Thus, the circulation sub is only able to stir up cuttings close to the sub. This is the same problem presented by the hydraulic oscillator described hereinabove.
If the port is large enough and the flow rate through the nozzle is significant enough, then the fluid along the length of the drill string could be placed into turbulent flow. Achieving turbulent flow along at least a substantial portion of the drill string present in the deviated portion of the wellbore would produce sufficient cuttings removal. However, such ports create fluid flow volumes and rates that tend to erode the borehole wall. A large port opening combined with greater fluid velocities creates a fluid pressure able to achieve high turbulence. Unfortunately, the fluid at high velocities impinges on the surrounding formation, thereby causing erosion.
Even assuming borehole erosion was not a problem, not enough drilling fluid can flow through the CT to provide sufficient fluid pressure through an enlarged port. There is a finite diameter of the internal bore of the CT. The volume of fluid required to get turbulence in the annulus is extremely high so that the back pressure along the tube exceeds the burst pressure of the tube. In other words, the CT cannot withstand the pressure required to pump enough fluid through this small diameter bore to achieve turbulent flow in the annulus using CT. The '011 patent teaches stopping drilling and diverting all flow through the port, but even this does not achieve turbulence in the annulus using CT. The '011 patent discloses an increase in the fluid flow rate, but that increase does not achieve turbulence.
The '011 patent also teaches forming the CT into a helix, thereby reducing the contact of the drill pipe along the bottom of the hole. This method requires pushing down on the CT from the surface. This may be done using the injector head on the rig 120. As illustrated in FIG. 10B, the force exerted on drill pipe 10 causes it to buckle and coil up in the borehole. However, most of the helix formed by the CT is not located at the bottom of the borehole using this method but above the deviated borehole. Ideally, the helix only touches the bottom of the borehole at certain points along the helix, thereby increasing the fluid flow around and removal rate of cuttings 20. However, there are various problems with this method. For example, when force is applied to the top of the CT, resistance is greatest at the top of the borehole. This causes the helical lock up to occur high in the borehole rather than at the lower end of the borehole, where the highly deviated portion of the well bore and bit are located.
None of the above mentioned devices or methods have provided adequate results for properly cleaning cuttings from a deviated wellbore. The present invention overcomes deficiencies of the prior art.